Pampa Energía S.A. (PAMP) Earnings Call Transcript & Summary

Telling you that this event is being recorded. [Operator Instructions] Before proceeding, please read the disclaimer in the second page of our presentation. Let me mention that forward-looking statements are based on Pampa Energia's management beliefs and assumptions and information currently available to the company. They involve risks, uncertainties and assumptions because they are related to future events that may or may not occur. Investors should understand that general economic and industry conditions and other operating factors could also affect the future results of Pampa Energia and could cause results to differ materially from those expressed in such forward-looking statements. Now I will turn the video conference over to Lida. Please go ahead.

Hi. Thank you, Raquel. Hello, everyone, and thank you for joining our conference call. I will make a quick summary of the Q2. You may find more details in our earnings release and financial statements. Today, we are having a Q&A with our CFO, Mr. Nicolas Mindlin; Mr. Horacio Turri, our Head of the Pampa Energia is here and Adolfo Zuberbuhler, our Head of Finance, is also here. Unfortunately, our CEO, Gustavo Mariani can't join us today because he is Pakaka, hosting our [indiscernible]. The gas production is what definitely stands out the quarter's figures. Again, we have beaten all company records, delivering a 37% increase year-on-year in Q2 and recording a new daily record high of 16.8 million cubiters per day. The output search is explained by the latest land gas contract. We've been awarded enabled by the new pipeline built last year. It also helped the early winter freeze driving retail and thermal power generation. The production increase is back by shale gas, harvesting the campaign we began last year. Shale gas now represents almost half of our total outlook this quarter, a significant increase compared to last year's 23%. Therefore, this quarter, the adjusted EBITDA amounted to $288 million, an increase of 30% compared to last year's figure, mainly because of the gas outperformance and PGS contribution, which surged by the 675% tariffing hike granted in Ito. Lower gas exports sales to industries and thermal dispatch partially offset this effects. The quarter-on-quarter increase is explained by the seasonality in commensurate recorded in Q1 and last year Q4. It is worth noting that almost 80% of the quarter's EBITDA was dollar linked, and the share now is led by DNB, which is mainly due to the gas production. CapEx Q2 is 28% lower year-on-year, mainly because in Q3 in 2023, we had a strong shale gas drilling and completion campaign and the construction of PEPE 4. This was partially offset by the last diversements of PEPE 6, which is estimated to be fully commissioned by October this year and the beginning of the pilot plan for shale oil in Bancolderana. Moving on to the Power Generation segment. As seen on Slide 4 -- 5, sorry, we posted an adjusted EBITDA of $106 million in Q2. This is 9% higher year-on-year, mainly explained by lower operating costs, the full commissioning of PEPE 4 in June last year and the strong spot sales in AGEERA. Partially offset by reduced Energia to sales, which is in line with the decline in industrial activity in addition to Mario Cebreiro's divestment last year. Q2 dispatch increased 3% year-on-year. This is mainly due to the lower gas availability for thermal dispatch that mainly affected our CCGT, partially offset by a better dispatch in the old CCGT in Genelba, which in Q2 last year had more days out of service for maintenance, higher water levels at Mendoza Hydros and they are the force contribution. Take or pay capacity payment, especially from PEPE's explains most of the EBITDA. It is driven by availability and in Q2, we reached 98% availability. This is higher than last year's 95%, mainly due to the previous year's thermal outages that we mentioned. So now turning -- let me give you a quick brief on PEPE 6, the expansion, the project, it's highly advanced, 94% between July and -- between July and August, 10 test wind turbines were commissioned by CAMMESA, totalling 45 megawatts. We are testing to commission another 4. The 500 kV high-voltage grid and transformer stations have been fully energized as well as spread with wind turbine circuits. Estimated fuel will be in October. And PEPE 6 energy will be sold under B2B PPAs in Mattel. Going on, on Slide 8, our E&P business posted an adjusted EBITDA of $121 million in Q2. This is 24% higher year-on-year. This increase was driven by plan gas island unlocked by the commissioning of the new test partner, which we were awarded a long-term contract for 4.8 million cubic meters per day, flat during the year. We -- the early freeze also helped lower gas exports and sales to industries offset this. In Q2, our total production average was 91,000 barrels per day. This is 35% higher than last year. When we sum coil just represented 6% of our ERP output and 50% of the segment's revenue. Total gas just keeps taking the lead, representing 94% of our total production. Higher maintenance and treatment costs due to the increased activity and explain that our total lifting costs grew by 11% year-on-year. Still, the rising output possibly impact the listed cost per BOE, which decreased 17% year-on-year, recording $5.3 per BOE and monetizing the economies of scale. Quickly commenting on gas. Our production in Q2 increased by 37% year-over-year and 24% quarter-on-quarter. This is averaging almost 50 million units per day in the quarter. As commented before, shale gas is the main contributor here and 63% of the quarter's production came from Mangrullo and 23% from Sierra Chata, our flagship shale gas field. Sierra Chata production grew 50% year-on-year without connecting or drilling a well core, while Mangrullo experienced 45% search with only 3 wells hiding. The average gas price over the quarter stood at $4 per million BTU. This is 14% down due to the lower exports to Chile. As you can see right below the higher deliveries of local gas were testing for thermal power generation. This is a quick review on Rincon de Aranda sharing the promising results. Horacio shortly will comment more on the Q&A. As you can see here, our well performance is within the range in our neighboring shale oil blocks and our daily production reached above 1,600 barrels per day once we connected the shut-in well issue. We have already placed a drilling rate in the block to start reading a pad of 4 wells was another pad next year. You mean to produce by mid-next year and reaching plateau production between 40,000 and 45,000 barrels per day by 2027. The petrochemical business, went to another business posted a $15 million EBITDA in Q2. This is 50% growth year-on-year, mainly because of the higher sales of reforming and improved exports of XVR margins, offset by the domestic sales due to the economic downturn. Hence, the export share is getting more and more important. Moving on to Slide 12. On Slide 12. We show the restricted group figures that reflect the bond perimeter. In Q2, we recorded a free cash flow of $60 million. Our working capital have recovered since capital last quarter. As of today, days of sales of standing is 55 days total. This is -- this means a delay of only 13 days. The payment normalization allow us to cancel that. So the net debt is significantly below last quarter, as you can see here. In summary, we increased $69 million of net cash in the quarter, achieving $914 million cash position by the end of the period. Well, this slide shows our consolidated financial position, including our affiliates of that ownership. But let's keep it focusing on restricted group figures. We posted a gross debt of $1.6 billion. This is 3% lower year-on-year and a 5% growth in cash after selling peso debt and depreciation of the peso. 92% of the gross debt is in U.S. dollars. The net debt recorded $691 million. This is a 12% year-on-year lower and onetime to last 12 months EBITDA net leverage. And the average life was 2.6 million years and until 2027, which is don't place any relevant debt maturity. So this concludes our presentation. Now I will turn the word to Rachel, who will poll for the questions. Thank you very much.

Thank you very much, Lida. So the floor is now open for questions. [Operator Instructions] Our first question comes from Alejandra Andrade from JPMorgan. First one is this , how are CAMMESA pyments -- she wants to know how CAMMESA payments are nowadays.

Hello. Hello, everyone begin to come in. Okay. So CAMMESA is staying quite well. As of today, we are not experiencing any delay, which is in line with historical minimums as Lida show in the presentation. On the other hand, Horacio has been paying with a delay of almost Aman, but we understand that this will normalize in the coming months. And in any case, we are seeing we will and reasonable delays in line with the historical minimums that we have seen.

In line with this, she also one also asks the $23 million impairments are unrecognized CAMMESA interests.

Yes. So as we communicated at the time, we are accepting CAMMESA's proposal to certain transactions for summary with the 38 months. So this proposal did not recognize accrue interest. So considering the on market prices at the time of the payment, we recognized a loss of $53 million, of which $23 million were unrecognized interest.

The third question of Alejandra, she ask how are the infrastructure projects progressing.

Good morning, everybody. Well, we have 2 main lines of infrastructure, the gas pipelines and the oil pipelines. In terms of -- let's go first to the gas pipelines. We are probably going to see the end of the reversion of the Noah pipeline by September or October of this year. So this will provide gas to the north of Argentina and reduce considerably the imports from Bolivia. On the other hand, TGS has already presented initiative Apria to the government in order to expand the transportation capacity of the existing network vision pipeline. With the addition of compression in the first tranche and some works in the TGS infrastructure that would boost the capacity transportation or the transportation capacity to approximately 14 million cubic meters per day of additional gas. This is currently being already presented to the government and is being analyzed. It's a very important infrastructure project to be taken into account. In terms of oil, we will have by March, April of next year, the Duplicar project of OldelVal, already commissioned, that will give additional 300,000 barrels per day of transportation capacity. We will also have the tranche 1 of the Vaca Muerta Sur project from YPF going from Loma Campana to Asen call this the collector of the main pipeline that is also in project in work progress now in the engineering phase, which is the connection of [indisccernilble] that will be commissioned by the first tranche by September with approximately 180,000 barrels per day and an additional 180,000 in September '26 and an additional 180,000 barrels per day by September of '27. And currently, they are analyzing the possibility of an additional 20,000 cubic meters more or 120,000 barrels more by the end of -- by September 27. This basically resumes the new infrastructure projects that are currently in progress in Argentina.

Last question from Alexandra she ask if we have expectations of returning to international market.

Okay. So this is on question. So we know there is currently an interesting window in the market for Argentine corporates. And as you know, our financial position is quite solid, and our next significant maturity is in January 2027. This is a BRL 750 million bond with a 7.5% coupon, which is below the yields of Pampa bonds right now and comparables and recent issuance from companies, for example, this year. And on the other hand, our cash position of nearly $1 million allows us to comfortably meet our the maturities and growth plans, such as Rincon de Aranda in the coming years. So for this reason, we are not in a hurry to undertake a liability management at the moment and to tap the markets, but we will closely monitor market conditions and do not rule out doing something early if the conditions are favorable or for example, if there is an M&A opportunity in the market.

The next question comes from Alejandro Michelis from Jefferies. He asked what participation can we expect from Pampa in the recently announced LNG export project.

Okay. We definitely will have a very active participation in the LNG export project. We are still in the process of analyzing the project and the -- our participation, but it's definitely the way out to our massive gas resources in Vaca Muerta.

Next questions come from Marina Mertens from Latin Securities. First one is Rincon de Aranda has delivered promising results. How do you anticipate crude oil production will develop in 2024 and 2025, given the planned midstream expansions and what additional equation capacity will be needed to meet your 2027 production targets?

Okay. In 2024, we don't foresee an increase in our production in Rincon de Aranda, basically at 2 wells that are already being hooked into the production lines. By 2025, as Lida mentioned before, we will be probably drilling and completing 2 pads, and that will give us the possibility of boosting our production to around 10,000 to 12,000 barrels per day, and that matches as well our transportation capacity from underbaland the possibility of acquiring additional capacity from companies that will have idle transportation capacity in the Duplicar project. The -- by 2027, we foresee, as I mentioned before, that the Vaca Muerta [indiscernible] of YPF will be finished. And we have an overall capacity contracted of approximately 48,000 barrels. So hopefully, by the end of 2027, at least our aim is to be in the range of 45,000 to 48,000 barrels per day.

Next question from Marina [indiscernible]. Considering the increase in natural gas production, is it realistic to expect that it could remain stable through the summer on local demand declines?

Well, Argentina is a seasonal market with a strong component of domestic demand. So I don't think it's realistic to think that the demand will be constant during the off-peak or the non-winter set.

Next question comes from Bruno Montanari from Morgan Stanley. First one says, how is natural gas demand performing into third quarter of 2024. Can we expect higher volumes versus this quarter?

Okay. Well, so far, we only have 1 month of the third quarter, which is July. In July last year, we delivered around 10.8 million cubic meters per day compared to 15.3% this year. So we have 42% up July '24, '23 and August is just starting. So it's hard to say what's going to happen because it's very much variable depending on the -- particularly on the weather.

Next question from Bruno is, what is the potential maximum volume of natural gas production once [indiscernible] the second tranche is delivered? And how much would be at to achieve that production.

Okay. We were awarded in the last round of the plan gas with the 4.8 million cubic meters per day on a flat basis. So the commissioning of the compression plans do not change our participation in plan gas. So we already reached our demand on plan gas basis. So we don't see an additional production due to the -- and I understand that you are asking about the commissioning of the 2 compression plans. So we don't see an additional capacity affecting the Pampa's demand on plan gas. So that was the first question and the other one in order to keep the production levels that we have both plan gas and plus exports plus industries, we foresee approximately 4 to 6 wells being drilled per year in order to just keep the constant production rates. So that would amount to approximately $100 million per year with no increase in our production curve, just keeping our capacities.

The last question from Bruno, says, can you talk about the evolution of the project to develop the company's shale oil acreage? Is the company on track to deliver the plan for 40,000 barrels per day plateau by 2027. What are the infrastructure bottlenecks and investments required to reach the production plateau.

Okay. Well, I already mentioned that we are currently drilling our second part in Rincon de Aranda. And we will be drilling 2 parts, additional pads in 2025. The bottlenecks basically have to do with treatment and transportation. In terms of treatment, we are already starting the construction of the all the necessary evacuation pipelines and pipelines in terms of oil pipelines and gas pipelines and temporary production facilities, both owned by Pampa and eventually being negotiated with neighbors in order to be able to deliver those 10,000 to 12,000 barrels per day I mentioned before by 2025. And also, we are currently finishing the engineering of our central processing facility that we have 4 blocks, basically, the oil plant, the gas treatment plant, the water disposal plant and the generation plant that will be ready by May 2026 for the first tranche of 3,500 cubic meters per day. And by September, October '26, the second tranche of our addition of 3,500 totaling 7,000 cubic meters per day or 42,000 barrels per day. So in parallel with our evaluation and treatment from the Rincon de Aranda itself, we are currently negotiating with YPF, our participation in the Vaca Muerta Sur, connecting Asan to Punta Colorado for, again, I mentioned before, 48,000 barrels per day. We already have contracted with YPF, the transportation from Loma Campana to Asen through the contract of the Vaca Muerta Surtramouna.

Next question come from Ann Mill from Bank of America. First one is, can you give us an update on the construction of barriers infrastructure needed to grow Argentina and Petronas business in Argentina? If there are any delays, how do you think they will be.

I think we already covered this.

Okay. And next one is Pampa looking at any other nonconventional oil areas at the moment?

We are always looking at new opportunities.

Okay. And the last one is, where do you see Pampa hydrocarbon production 5 years from now in terms of volumes and breakdown between natural gas and crude oil.

Okay. In terms of oil, we already mentioned that our aim is to reach a plateau of around 45,000 to 50,000 barrels per day. And that's what we're probably going to be keeping as our goal. Eventually, we are looking at new opportunities, but what we have today in the pipeline is that. And in terms of natural gas, until 2028, we have the plan gas, which are current -- basically the current volumes that we are delivering into the market. We still have to see what happens with the expansion of the gas pipelines. As I mentioned before, that represents around 14 million cubic meters per day. I guess that probably we will keep around 20% to 30% out of that market share. So we are talking 3 million to 4 additional million cubic meters per day of natural gas during the winter season, that's approximately 100 to 120 days. So basically, those are the main drivers of our future production, not to mention the possibility of the development of the LNG projects that we mentioned before.

Thank you, Marcio. Next question comes from Gustavo Faria from Bank of America. First one, he says, how do you see the demand for gas export in the second half of this year? And could you give a little disclosure on the export prices in the second half of 2024.

Okay. For the second half of 2024, we have committed 600,000 cubic meters per day to Chile through Gasandes. The minimum price and the price at the same time, that was approved by the Secretary of Energy, 7% of Brent, which turns out to be around $5.5 per million BTU well ahead.

Next question from Gustavo. He says we saw an important drop in the lifting cost in the second quarter of 2024. Do you see any room for additional listing cost improvement in the gas upstream segment? Or do you consider the current level as the plateau?

No, we consider that what we reached this is probably the plateau. We won't be seeing any substantial decrease in the future.

Next question comes from Ignacio [indiscernible] from I[indiscernible] First of all, he says, regarding the future increases in regulated prices, do you have any estimation of when these hikes will finally translate into effectively higher income for the company rather than merely substituting subseas.

It's a good question. So less subsidies means less dependence on CAMMESA and it's more reliant on the demand. Basically, the higher hikes on the electricity, the payment electricity role price in the final bills that means lesser subsidies that means lesser subsidies for CAMMESA and then CAMMESA help pay us faster sample. It's not going to be materially we be getting more money. We, as a company, need more money, but meaning we're getting a better quality on the collections on the payment side and the receivables. This is mainly the biggest importance here behind the lowering of subsidies. Another thing that is very important is that the other regulated prices, the gas price and the final deal, the higher the gas prices for retail, the lower the subsidies it is. So we collect less plant gas compensation. But again, we collected for the distribution. So I mean it's getting a better credit profile and a lesser dependence on the government's diversements. Just to note is, the government just passed a few actually, they passed last June, the regulated prices until the end of this year for electricity and for gas. They already put the outlook for what's going to be the subsidies until the end of the year as well? Or what's -- what kind of subsidies will be for those that are under retail social tariff or middle income as well as the government just passed just a few days ago, the monthly incremental increase for inflation, for transmission, for Transener, 4% for TGS and 3% for legacy price legacy energy.

Next question from Ignacio is about gas production volumes going forward. Do you see these levels of production being sustained in the forthcoming quarters? Or was this big due to an exceptionally cooler quarter?

I think we covered that.

Okay. So the final question is, are there any M&A opportunities being considered or all the cash will be devoted to CapEx in order to accelerate and ramp up in Rincon de Aranda.

Okay. So we know that our financial position and level of indebtness allow us to grow inorganically, and we have been analyzing all the opportunities that have been in the market recently, particularly in our core segments, including unconventional areas, but unfortunately, no attractive opportunities in terms of price appeared yet. So currently, developing our vast gas fields such as Mangrullo and Sierra Chata and now in Rincon de Aranda in oil, along with all the necessary infrastructure is much more profitable for Pampa and paying a high entry price for new assets. So as always, we remain open to potential opportunities that may appear in the market and are always evaluating what is best for the company, but we haven't found anything interesting so far.

Next question comes from Fernando [indiscernible]. He asked, have you discuss alternatives with the government regarding the canceled Genelba 3 greenfield and Baran expansion projects.

So as Nicole, thank you. We have presented 2 projects. The big ones, the 300 megawatts, of course, it's not going to pursue because this we can sell. But the other one, actually, we did present, we wanted Well, the telecom oxygen is canceled, but we're doing it anyway. This is a way to improve efficiency even further the efficiency of the plant, and we are doing a very small CapEx is $50 million or increasing 11 mega watts, so we're good.

Next question comes from Walter Chiarvesio from Santander. First one is, can you please update on Rincon de Aranda total region production cut if equation capacity, et cetera?

I think we already covered this.

Yes. Okay. Next one, any update on potential energy price regimes to be introduced by the regulator.

We have already covered that.

We covered that.

And next question comes from Florencia Mayorga from MetLife. So said the deterioration.

That's what she told me she's okay.

Okay. So next question comes from Per Lederer. She wants to know. Do you have some color related to export in terms of restrictions. Can you sell that one abroad -- like very broad sorry.

We are talking about oil, gas or electricity, but I'm not so sure about it. If it is oil, there's no restriction whatsoever. And in terms of gas, it's the same thing. We are restricted by the transportation capacity. But there's no regulatory restriction under the new ready access in order to export a free market.

Now yes, from [indiscernible]. Regarding hydro, we are recognizing a provision of termination of Mendoza Hydros, which was the value? Any update on next steps.

Yes, we've been making provisions. If you can see quarter-on-quarter in light of this very close expiration. The only update we have is that we'll be granted a 12-month extension. So there's -- this is complicated because there's 2 concessions in this hydro that is one is the provincial or one is the national one. The provincial one has been wanted for 12 months, but the state, the national one, it's only for 6 months, external or another 6 months. So in light of this, it looks like it's going to -- is wells will be expiring. If there's no extension provided granted on November of this year. We'll see. It's -- that's how it is.

And next question comes from Ludovic [indiscenible] First one is, according to the press, some companies have signed export contracts of natural gas to Brazil. With the reduction of North gas pipeline expands to Brazil too?

Yes. We got export gas to Brazil. Absolutely. And we can also export gas to the north of Chile, which is a market that will compete with Brazil. Definitely, we can do that.

And next question from [indiscernible] Luis Mauro. After the recent increase in gas prices and electricity prices, how much of the cost is paid by end users for gas and electricity.

For electricity, the other day, I got the number. It's -- the cost was $91 is the average cost of the grid and the coverage was 61%. So it's pretty -- the coverage was 61%. It's pretty high. Last year was the coverage was 20%. So it's increasing. The government has diverse the other 40%, right? For example, for users, retail users that are non subsidies such as me, I'm not subsidize at all. I am paying my bills $72 per megawatt hour. Of course, against the real cost, 91 still subsidized, but been hiked from $20 last year. So it's been increasing high. Then in gas, gas I don't remember the coverage because winter the prices go up very much because of the liquid, it's difficult to access. But for example, full on substrate people like such me, I'm paying $3.3 per the BTU. Last year, I was paying $1.5 per BTU it's been increased. And low-income people are paying instead of cents $0.30, $0.20. Now they're paying 1.8, but just for a block, if their consumer and that if they express consumption, they have to pay the full care that it's 3.3%. So the idea is to lift it up the prices little by little. In the case of the people that can afford such as myself, it's the full there, but it's still a little bit lower than real cost, but very close, as you can see.

Okay. And that was -- do we have more questions?

So next question comes from [indiscernible]. You have just announced a share buyback program. But you consider to return more cash to shareholders.

So we just announced the program, and you are already asking for more. Now in the last 5 years, less than 5 years, we have repurchased almost $600 million of shares at an average price of $22 per ADR. And now we are announcing a new program. So that's all for now. We are not considering anything more.

So we don't had any more questions. I think I don't any more questions. If you have any questions about the financial statements or anything you can just do it, we just uploaded in our website, the amines. We have all the backup information there. I think we hit the top of the hour. We appreciate very much you joining us on this call. I appreciate you Horacio, and Nico for joining us for the Q&A. Any questions you may have, please send us an e-mail, we will be more than happy to help you. I hope a bit to a good day.

Thank you very much. Good day.